FAILURE ANALYSIS OF SHELL AND TUBE HEAT EXCHANGER full report

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FAILURE ANALYSIS OF SHELL AND TUBE HEAT EXCHANGER
PROJECT REPORT
Submitted by
ALEX BABY ARUN M V JAIN RAJ .V VIJEESH VIJAYAN
ABSTRACT
Tar column recoiled E4509 in the phenol plant of HOCL found failed in service un like any other exchanger s in phenol manufacturing process .Each failure very high cost to HOCL in terms of production loss due to down time for maintence and due to the loss of therminol liquid to the process .the loss due to each failure found to be nearly RS 1.5 chore >the cost of tube bundle in SS-316 is SOlacks and the cost of incoloy-825 tube bundle is 50 lacks. The failure analysis of this exchanger was found most interesting and during these work modes of failures of heat exchanger was studied to conclude and recommend solution. Design of exchanger was the methodology used to analyse the problem. Reviewed the history of the exchanger .compared the capacity of the exchanger in various possible design conditions .the results and conclusion of the study will be very use full for HOCL in future planning process
CHAPTER-1 INTRODUCTION
We look up a project on heat exchanger, which is static equipment at Hindustan organic chemicals limited. Heat exchanger may be defined as equipment which transfers the energy from a hot fluid to a cold fluid with maximum rate and minimum investment and running cost.
It is used to reduce temperature of one process fluid , which is desirable cool ,by transferring heat to another fluid which is desirable to heat with out inter mixing the fluid or changing the physical state of the fluid
Heating is a vital operation in the petroleum and chemical refinery. Hence failure of a heat exchanger result ineffective transfer of energy. Normal operation of heat exchanger usually requires little operator attention .However, operating life of a hear exchanger can be drastically curtailed by improper start up and shut down practices. So properly planed executed maintenance schedule is in dispensable for ^very industries having heat exchangers on their main equipment in their process plant.
A detailed maintenance schedule of plant and machinery of an industry involves mainly monitoring without disturbing the operation of the plant as a whole.
A project titled "Failure analysis of shell and tube heat exchanger" presents an over view on different types of heat exchangers, their purposes advantages and disadvantages and the maintenance procedure adopted for smooth operation of the heat exchanger. The operation of heat exchanger involves the production of phenol from TAR COLUMN.
The case study deals with the failure analysis of heat exchanger and design is checked and then proper solutions are given to improve the effectiveness of heat exchanger.
ABOUT HINDUSTAN ORGANIC CHEMICALS LIMITED
The HOCL was in-corporated with a view to Set up manufacturing of chemical intermediates with the objectives of giving inputs to the development of downstream industrial units in sector like dyes and dye intermediates, drugs and pharmaceuticals, rubber chemicals, laminations, solvents etc. The first unit was set up at Rasayani in Maharashtra which commenced production in 1970. The second unit was started at Cochin in Kerala, which started production in 1987. In the year 1988 a subsidiary company viz Hindustan fluorocarbons Ltd. was commissioned at Hyderabad. The company is presently engaged in the manufacturing of a wide range of petrochemicals. The major products serve as import substitutes.
The HOCL is a public limited company, which is managed by a board of directors consisting of six members.
fThe management is assisted by a team of well qualified and experienced professionals in technical financial safety, marketing, legal and other key areas.
COCHIN UNIT
Commissioning of Cochin (phenol and acetone) in 1987 headed another path breaking step of HOCL entry into the field of petrochemicals. The Cochin plant has an installed capacity of 24,000 TPA of acetone and 409000 TP A of phenol; both are highly versatile organic chemicals. The Cochin unit comprises of three states of plant, Viz.
1. Propylene recovery plant
2. Cumene plant
3. Phenol plant
4. Hydrogen peroxide
Universal oil products inc (UOP\ USA One of the] world leaders in the field of petrochemicals has supplied the technology for phenol-cumene plant. Detailed engineering for all the plants and also off-site work was done by FEDO and Engineers Indian Ltd. Provided engineering for the propylene plant and Effluent treatment plant.
The company has achieved the ISO 9002 certification for its quality measures in the production process and ISO 14,000 for environmental quality standards. The entire operation of plant is totally Automatic remote controlled. Continuous on-line monitoring of the process results in perfect quality control.
The organization has high tech safety features to minimize hazards. Most modem effluent treatment plant assures complete safety to the enviroment confirming to international specifications. Latest energy conservation and optimisation concepts have been incorporated at the beginning stage. This is the first company to export Phenol and Acetone from .india.
State pollution control board has awarded the company with the certificate of merit for pollution control. Cochin plant was awarded with the best pollution control measures among chemical plants in the state of Kerala.
PLANT LAYOUT
25
24
23 22
J
4
5
6
7 8
9 10
11
20 13
14 15
16
21
20 17
18
19
PARTS AND COMPONENTS
1. H2 02 plant
2. Main tankage
3. H2 plant 1
4. Compressor house
5. DM plant
5. DM plant -
6. Boiler
7. H2 Plant 2
8. North Tankage
9. Fractionation section
10. Hot oil plant
11. Tar cracking plant
12. Cumox plant
13. Cumene plant
14. South tankage
15. Cumene storage
16. Effluent treatment plant
17. Cumene storage
18. Main receiving station
19. Captive power plant
20. Main control room
21. Propylene plant
22. Propylene storage
23. LPG storage
24. Cooling tower
25. Administrative block
26. Pre-treatment plant
27. Water storage
28. Emergency escape road.
CHAPTER-2 HEAT EXCHANGERS
Heating, Condensing and Cooling are operations vital to the petroleum and chemical refinery. These operations are accomplished mainly by tubular exchanger equipment (Shell and Tube). Other equipments used for condensing and cooling are air cooled heat exchanger and box coolers.
A heat exchanger may be defined as an equipment which transfers the energy from the hot fluid to a cold fluid or vice versa, with maximum rate and minimum investment and running cost. The heat exchanger is used to reduce the temperature of one process fluid, which is desirable to heat without intermixing the fluids or changing the physical state of the fluids.
Condensers are used to cool the temperature of a process vapour to the point where it will become a liquid by the transfer of heat to another fluid without intermixing the fluids. Water or air is used to condense the vapour.
In HOCL heat exchangers are mainly used for condensing the hot vapours of the product obtained by crude distillation and storing them in the liquid form.
COMPONENTS OF HEAT EXCHANGERS
1. Stationary Head-Channel 15. Floating Tubes sheet
2. Stationary Head-Bonnel 16. Floating Head Cover
The figure given below shows a typical heat exchanger and its components
3. Stationary Head Flange
4. Channel Cover
5. Stationary Head Nozzle
6. Stationary Tube sheet
7. Tubes
8. Shell
9. Shell cover
10. Shell Flange
11. Shell flange- Read Head End
12. Shell Nozzle
13. Shell Cover Flange
14. Expansion joint
17. Floating Head Flange
18. Floating Head Baring Device
19. Split Shear Ring
20. Slip-On Backing Flange
21. Floating Head Cover-External
22. Floating Tube Sheet Skurt
23. Packing Box
24. Packing
25. Packing Gland
26. Lantern Ring
27. Tierods and Spacers
28. Transverse Baffles/support Plates
2.1 TYPES OF HEAT EXCHANGER
In order to meet the widely varying applications several types of heat exchangers have been developed which are classified on the basis of nature of heat exchange process, relative direction of fluid motion, design and constructional features and physical state of fluids.
NATURE OF HEAT EXCHANGE PROCESS.
Heat exchangers on the basis of nature of heat exchange process are classifieds
as.
i. Direct contact opened heat exchagers.
ii. Indirect contact heat exchangers.
a. Regenerators.
b. Recuperator
DIRECT CONTACT H.EAT EXCHANGER
Figure 2
In a direct contact heat exchanger, exchange of heat takes place by direct mixing of hot and cold fluids and transfer of heat and mass takes place simultaneously. The use of such units is made under conditions where mixing of two fluids is either harmless or desirable.
II. Indirect Contact Heat Exchangers
In this type of heat exchangers, the heat transfer between two fluids could be carried out by transmission through wall which separates the two fluids.
a. Regenerator
In a regenerator type of heat exchangers the hot and cold fluids pass alternatively through a space containing solid particles (matrix), these particles providing alternatively a sink and a source for heat flow. Example. IC Engine and Gas Turbine.
The performance of these regenerators is affected by the following parameters
1. Heat capacity of Regenerating Materials.
2. The rate of absorption
3. The release of heat.
Advantages of regenerators are :
1. Higher heat transfer coefficient.
2. Less weight per KW of the plant.
3. Minimum pressure loss
4. Quick response to load variations
5. Small bulk weight.
Disadvantages of regenerators are:
1. Costlier compared to recuperative heat exchangers.
2. Leakage is the main trouble ; therefore, perfect sealing is required,
b. Recuperators
Recuperator is the most important type of heat exchanger in which the following fluids exchanging heat are on either side of dividing wall. These heat exchangers are used when two fluids cannot be allowed to mix i.e., when the mixing is undesirable.
Examples: - 1. Oil Coolers, Intercoolers, 2. Automobile radiators. Advantageous of a recuperator are.
1. Easy construction
2. More economical
3. More surface area for heat transfer.
4. Much suitable for stationary plants.
2. Relative Direction of fluid motion
According to relative directions of two fluids streams the heat exchangers are classified into following three categories.
i. Parallel flow or unidirectional flow.
ii. Counter flow.
ii. Cross flow
i. Parallel flow heat exchanger.
' In parallel flow heat exchanger as the name suggest the two fluid streams (hot
and cold) travel in the same direction. The two streams enter at one end and leave at the other end. The flow arrangements and variations of temperatures of the fluid stream in case paralled flow heat exchangers are shown in figure. It is evident from the figure that the temperature difference between the hot and the cold fluid goes on decreasing from inlet to outlet. Since this type of heat exchangers needs a large areas of heat transfer it is rarely used in practice.
Example : oil coolers, oil heaters, water heaters
As the two fluids separated by a wall, this type of heat exchanger may be called parallel flow recuperated or surface heat exchanger.
Tai
Tbi
1/1 . ; in') in
Tbo
Temperature distribution along tube axis. FIGURE 3
ii. Counter Flow Heat Exchanger.
In a counter flow heat exchanger, the two fluid flow in opposite direction. The hot and cold fluid enters the opposite ends. The flow arrangements and temperature distribution for such a heat exchanger are shown in figure. The temperature difference between the fluids remains more or less nearly constant. This type of heat exchanger due to counter flow gives maximum rate of heat transfer for a given surface area. Hence such heat exchangers are most favored for heating and cooling fluids.
INLET
7*F
7Sf
7B+ v OUTLET
Figure 4 Counter Flow Heat Exchange
ii. Cross Flow Heat Exchanger
In cross flow heat exchangers the two fluids (hot and cold) cross one another in space usually at right angles. Fig. Shows a schematic diagram of common arrangements of cross flow heat exchangers.
Q ID
LL "
h O
X i
c
BAFFLES j
COLD FLUID (IN)
_j O
-Q
3
o
X
COLD FLUID (UOT)
CROSS FLOW HEAT EXCHANGER Figure 5
Refer Figure : Hot fluid flow in the separate column and there is mixing in the fluid streams. The cold fluid is perfectly mixed as its flow through the exchanger. The temperature of this mixed fluid will be uniform across any section, and will vary only in the directions of the flow. Example: cooling unit of refrigeration system.
Refer figure: In this case each of the fluid follows a prescribed path and is unmixed as it flows through heat exchanger. Hence the temperature of the fluid leaving the heater section is not uniform.
Example: automobile radiator
3. DESIGN AND CONSTRUCTIONAL FEATURES.
On the basis of design and constructional features, the heat exchanger are classified as under
i. Concentric Tubes
In this type, two concentric tubes are used each carrying one of the fluids. The
direction flow may be parallel or counted as depicted in figure. The effectiveness of the heat exchanger is increased by using swirling flow.
ii. Shell and Tube
In this type of heat exchanger one of the fluid flows through a bundle of tube ' enclosed by a shell. The other fluid is forced through the shell and it flows over the I outside of surface of the tubes. Such an arrangements employed where reliability and heat transfer effectiveness are important. With the use of multiple tubes heat transfer
rate is amply improved due to increased surface area.
ii. Multiple Shell and Tube Passes.
Shell fiuld
f^r S X 7 \ \
J V / I \ / j \ / k
I 11 1 JM" ^^J> V '
Baffles
Tube fluid
/ \ I 7
7 \
\ 7 I \
J \ l 3S
I 1
7 * v
LT3
Twti-shel) pass and four-tube pass haat exchanger
Figure 6
Multiple shell and tube passes are used for enhancing the overall heat transfer. Multiple shell passes is possible where the fluid flowing through the shell is re-routed. The shell side fluid is forced to flow back and forth across the tubes in the by baffles. Multiple tube pass exchangers are those which re-route the fluid through tubes opposite direction
HOT FLUID (OUT)
One shell pass and two tube pass heat exchanger
Figure 7
iv. Compact Heat Exchanger
These are special purpose heat exchangers and have a very large transfer surface area per unit volume of the exchanger. They are generally employed the convective heat transfer co-efficient associated with one of the fluids is much smaller than that associated with the other fluid.
Example : Plate - Fin, flattened fin tube exchangers.
4. PHYSICAL STATE OF FLUIDS.
Depending upon the physical state of the fluids the heat exchangers are classified as follows :
i. Condenser
ii. Evaporators
i. Condenser
In a condenser, the condensing fluid remains at constant temperature through out the exchanger, while the temperature of colder fluid gradually increases from inlet to outlet. The hot fluid losses latent part of fluid which is accepted by the colder fluid.
ii. Evaporators
In this case, the boiling fluid remains at constant temperature while the temperature of the hot fluid gradually decreases from inlet to outlet.
2.2 OPERATION OF HEAT EXCHANGER.
Normal operation of heat exchangers usually requires little operator
attention. However, operating life of a heat exchanger can be drastically
curtailed by
improper start up and shut down practices. Some common problems are :
i. Tube failure due to 'water hammer' effect caused by opening the shell
inlet valve too quickly.
ii. Bending of the pass partition plate in the partition channel due to slung
flow from the tube inlet nozzle. Caused by rapid opening of the channel
inlet valve.
ii. Introduction of tube side fluid in a fixed tube sheet heat exchanger with
the shell side empty (since the resulting change in the tube metal
temperature may over stress the tube to tube sheet joint resulting in
the failure).
iv. Thermal stress induced cracking of thick sections in region of gross
structural discontinuity, such as tube sheet / channel junction in integral
design, due to rapid changes in the fluid temperature. In order to avoid
such problems start up and shut down of the equipments should be
carried out in a manner consistent with the original design basis.
" At times, heat exchangers are designed to operate under differential
pressure is the shell and the tube side pressure are always presents
simultaneously. The
operator should ensure that the design assumption of differential pressure is never violated. Including the period of start up and shut down, or the period of system pressure testing.
Other operational problems in heat exchanger are flow induced vibration, rapid tube failure, corrosion and erosion of the tube wall, tube joint failure, fluid level control difficulties and flanged joint leakage.
2.3. MAINTENANCE OF HEAT EXCHANGER
Operating problems in heat exchangers may be broadly classified into three groups.
i. Structural Problems
ii. Performance Problems
ii. Metallurgical problems
i. Structural Problems
Structural problems are the most serious; failure is often swift and
irreversible. Failures caused by flow - induced vibration of heat exchanger tubes over shadow all other structural failures. Tube to tube sheet joints failure is also a fequent operational problem.
The other type of structural failure encountered in heat exchanger operation is leakage from holted joints. Leaks frequently occured nozzle flanges due to moment loading of the joint caused by thermal expansion of the interconnecting piping. In some cases, non-temperature distribution in the tube sheet or cover in multiple pass design induces joint leakage. Replacement of the leaking gasekts with one having more appropriate loading and relaxation properties is usually the panacea for such structural problems.
ii. Performance Problems
The excessive tube fouling usually causes performance problems
Deposition of foul ants on the inside of the tube surface reduces the available flow area and increase the skin friction, causing an increase in pressure loss and decrease in heat transfer. Un even rates of fouling of tubes usually occur in units with low flow velocity design. Uneven fouling may occur on the shell side of the tubes due to a poor baffling scheme. Which leads to a flow misdistribution. Highly non-uniform fouling on severely modifies the metal temperature profile in some tubes resulting in large tubes - to tube sheet joint leads.
Thermal stresses in the internal of the heat exchanger can cause serious degradation of heat duty. The most obvious example is failure of welds joining pass partition plates to each other and to the channel.
ii. Metallurgical problems
Stress corrosion, galvanic corrosion, and erosion are the most requently
reported metallurgical problems. Care in the selection of material can eliminate most of these problems. Where the galvanic action cannot be completely eliminated. The use of waster anode is recommended.
ADVANTAGES AND DISADVANTAGES OF HEAT EXCHANGERS Advantages
1. Energy Savings.
2. No Additional boilers are needed.
3. Condensation provides less space and safety operations.
Disadvantages
1. The use of heat exchange causes the flow restriction, hence, additional pumps are required to correct the flow.
2. Friction losses
3. Operation difficulties such as flange leakage.
4. Failure of heat exchanger.
5. Maintenance cost and operating cost.
2.4 FOULING
In a heat exchanger during normal operations the tube surface gets covered by deposits of ash, soot, and dirt and scale etc. This phenomenon of rust formation and deposition fluid impurity is called fouling.
fouling Processes
1. Precipitation or crystallization fouling
2. Sedimentation or particulate fouling
3. Chemical reaction fouling or polymerization
4. Corrosion fouling
5. Biological fouling
6. Freeze fouling
Parameter affecting fouling
1. Velocity
2. Temperature
3. Water chemist
4. Tube materia]
Prevention of fouling
The following methods may be used to keep fouling minimum
1. Design of heat exchanger
2. Treatment of process system
3. By using clean system
Properties to be considered for selection of materials for heat exchang*
1. Physical properties
2. Mechanical Properties
3. Climatic Properties
4. Chemical Environment
5. Quality of Surface finish
6. Service File
7. Freedom from Noise
8. Reliability
Common failure to heat exchangers
1. Checking of tubes either expected or extra ordinary-.
2. Excessive transfer rates in heat exchanger
3. Increasing the pump pressure to maintain through out
4. Failure to clean rubes at regularly scheduled intervals.
5. Excessive temperature in heat exchanger
6. Lack of control of heat exchangers atmosphere to retard scaling.
7. Increased product temperature over a safe design unit
8. Unexpected radiation from refractory surface.
9. Unequal heating around the circumferences or along the length tubes.
Overall Heat Transfer Coefficient
Heat transfer in heat exchanger takes place mainly by conduction and convection. If a tube wall as separates the fluids shown in figure. The overall heat transfer co efficient is given by
Inner surface,
Ui
1/hi + ri/k In (ro /ri) + ri/ro x 1/ho
Outer surface
Uo
(ro /ri) 1/hi + ro/kxln ( ro/ri) x 1/ho
Where
Ui
Overall heat transfer coefficient inside the tube
Uo
= Overall heat transfer coefficient outside the tube
Hi
= Local convective heat transfer coefficient inside the tube
ho
= Local convective heat transfer coefficient inside the tube
ri
= Inside radius of the tube
ro
Outside radius of the tube
k = Conductive heat transfer coefficient of tube material.
U.A. = UoAo
Where
A = 2 r. L, Area inside the tube
A = 2 r L, Area outside the tube
0 o '
1 inoVn) 1 hi Ai 2TTKL h0A Figure 8
Consideration of fouling or scaling
Due to fouling the thermal resistance is increased and eventually the performance of heat exchangers lowers. Since it is difficult to ascertain the thickness and thermal conductivity of the scale deposits, the effect of sale on heat flowing considered by specifying an equivalent scale heat transfer coefficient hs. If hsj and hsQ be the heat transfer coefficient for the scale deposited on the inside and
outside surface respectively, than the thermal resistance to scale formation on the inside surface (RSj) and outside surface (RS0) are given by
RS - _J ,
A hs. i i
RSo = 1 .
Ahs
O 0
The reciprocal of the heat transfer coefficient, hs is called the following factor R f Thus R f = 1 /hs m2oc/w
Fouling factors are determined experimentally by testing the heat exchanger in both clean and dirty continuous. The fouling factor R f is thus
defined as :
Rf=(l/hr)= l/UH.t - 1/U .
v ' dirty clean
The heat transfer considering the thermal resistance due to scale formation, is given by
Q = 0.^) ,
l/A.h + 1/A.hs.+1/2 KLxIn(r r.)+l/A hs + 1/A h
11 11 v O. V 0 0 0 0
The overall heat transfer coefficient U based on the inner and outer surface of the inner tube is given by :
Ui - 1 ,
l/h. + R.+ r. KIn(r .r.) + r. / r . +R.. +r./r xl/h
1 II v O K 1 O 1010 O
Uo 1 ,
(r/r.)xl/h.+(r.r.)xRf. + r / k x In ( r / r .) + Rf + 1/h
v01/ 1 v O K 1 0 v 0 K 0
2.5 TYPES OF SERVICES
There are various types of services in which tubular exchangers are used in
petroleum and chemical processes listed below.
1. Heat Exchanger: It used to reduce the temperature of one process fluid, which
is desirable to cool by transfering heat to another fluid which is desirable to heat without intermixing the fluids or changing the physical state of the fluid.
2. Condenser: are used to reduce the temperature of a process vapour to the
point where it will become a liquid by the transfer of heat to another fluid without intermixing the fluid. Water or air is used to condense process vapour. The function results in a changing the physical state of the process vapour.
3. Coolers: They are used to cool a heat process liquid to a lower more desirable temperature by the transfer of heat to another fluid without intermixing the fluid. Water or air is usually used to cool process liquids. This function does not result in a changing physical state of the process liquid.
4. Evaporator: are used in the vaporization of a process liquid by either a process or utility liquid or vapor without intermixing the fluid. Many aporators are steam to vaporize a process liquid. This function results in a changing the physical state of the process vapour. When steam is used condensate is usually formed.
5. Re - boilers : are used in the partial vaporizations of a process fluid by either a process or utility liquid or vapor. Many re-boilers are steam to vaporize a process liquid.
2.6 TYPES OF FAILIURE
Stress Corrosion Cracking
Stress corrosion cracking is a failure mechanism that is caused by environment, susceptible material, and tensile stress. Temperature is a significant environmental factor affecting cracking.
For stress corrosion cracking to occur all three conditions must be met simultaneously. The component needs to be in a particular crack promoting environment, the component must be made of a susceptible material, and there must be tensile stresses above some minimum threshold value. An externally applied load is not required as the tensile stresses may be due to residual stresses in the material. The threshold stresses are commonly below the yield stress of the material.
Stress Corrosion Cracking Failures
Stress corrosion cracking is an insidious type of failure as it can occur without an externally applied load or at loads significantly below yield stress. Thus, catastrophic failure can occur without significant deformation or obvious deterioration of the component. Pitting is commonly associated with stress corrosion cracking phenomen
Figure.9 Stress Corrosion Cracking
Aluminum and stainless steel are well known for stress corrosion cracking problems. Owever, all metals are susceptible to stress corrosion cracking in the right environment.
Controlling Stress Corrosion Cracking
There are several methods to prevent stress corrosion cracking. One common method is proper selection of the appropriate material. A second method is to remove the chemical species that promotes cracking. Another method is to change the manufacturing process or design to reduce the tensile stresses. AMC can provide engineering expertise to prevent or reduce the likelihood of stress corrosion cracking in your components.
Failures of Heat Exchangers
Some common causes of failures in heat exchangers are listed below:
Pipe and tubing imperfections
Welding
Fabrication
Improper design
Improper materials
Improper operating conditions
Pitting
Stress-corrosion cracking (SCC)
Corrosion fatigue
General corrosion
Crevice corrosion
Design errors
oying
Selective leaching, or dealt
Erosion corrosion
Wear Failures
Wear may be defined as damage to a solid surface caused by the removal or displacement of material by the mechanical action of a contacting solid, liquid, or gas. It may cause significant surface damage and the damage is usually thought of as gradual deterioration. While the terminology of wear is unresolved, the following categories are commonly used.
Figure.10 Wear Failures
Adhesive wear
Adhesive wear has been commonly identified by the terms galling, or seizing Abrasive wear
Abrasive wear, or abrasion, is caused by the displacement of material from a solid surface due to hard particles or protuberances sliding along the surface
Erosive wear
Erosion, or erosive wear, is the loss of material from a solid surface due to relative motion in contact with a fluid that contains solid particles. More than one mechanism can be responsible for the wear observed on a particular part.
Pitting Corrosion
Pitting is a localized form of corrosive attack. Pitting corrosion is typified by the formation of holes or pits on the metal surface. Pitting can cause failure due to perforation while the total corrosion, as measured by weight loss, might be rather minimal. The rate of penetration may be 10 to 100 times that by general corrosion.
Pits may be rather small and difficult to detect. In some cases pits may be masked due to general corrosion. Pitting may take some time to initiate and develop to an easily viewable size.
Pitting occurs more readily in a stagnant environment. The aggressiveness of the corrodent will affect the rate of pitting. Some methods for reducing the effects of pitting corrosion are listed below:
Reduce the aggressiveness of the environment
Use more pitting resistant materials Uniform Corrosion
Uniform or general corrosion is typified by the rusting of steel. Other examples of uniform corrosion are the tarnishing of silver or the green patina associated with the corrosion of copper. General corrosion is rather predictable. The life of components can be estimated based on relatively simple immersion test results. Allowance for general corrosion is relatively simple and commonly employed when designing a component for a known environment.
Some common methods used to prevent or reduce general corrosion are listed below:
Coatings
Inhibitors
Cathodic protection
Proper materials selection
Figure.11 Uniform Corrosion
Corrosion Failures
Corrosion is chemically induced damage to a material that results in deterioration of the material and its properties. This may result in failure of the component. Several factors should be considered during a failure analysis to determine the affect corrosion played in a failure. Examples are listed below:
Type of corrosion
Corrosion rate
The extent of the corrosion
Interaction between corrosion and other failure mechanisms
Corrosion is is a normal, natural process. Corrosion can seldom be totally prevented, but it can be minimized or controlled by proper choice of material, design, coatings, and occasionally by changing the environment. Various types of metallic and nonmetallic coatings are regularly used to protect metal parts from corrosion.
Stress corrosion cracking
necessitates a tensile stress, which may be caused by residual stresses, and a specific environment to cause progressive fracture of a metal. Aluminum and stainless steel are well known for stress corrosion cracking problems. However, all metals are susceptible to stress corrosion cracking in the right environment.
Laboratory corrosion testing is frequently used in analysis but is difficult to correlate with actual service conditions. Variations in service conditions are sometimes difficult to duplicate in laboratory testing.
Corrosion Failures Analysis.
Identification of the metal or metals, environment the metal was subjected to, foreign matter and/or surface layer of the metal is beneficial in failure determination. Examples of some common types of corrosion are listed below:
Uniform corrosion
Pitting corrosion
Intergranular corrosion
Crevice corrosion
Galvanic corrosion
Stress corrosion cracking
Not all corrosion failures need a comprehensive failure analysis. At times a preliminary examination will provide enough information to show a simple analysis is adequate.
Fatigue Failures
Metal fatigue is caused by repeated cycling of of the load. It is a progressive localized damage due to fluctuating stresses and strains on the material. Metal fatigue cracks initiate and propagate in regions where the strain is most severe.
The process of fatigue consists of three stages:
Initial crack initiation
Progressive crack growth across
Final sudden fracture of the remaining cross section
S
Stress
Graph-1 S-N curve
Schematic of S-N Curve, showing incr.ease in fatigue life with decreasing
stresses
Stress Ratio
The most commonly used stress ratio is R, the ratio of the minimum stress to the maximum stress (Smin/Smax).
If the stresses are fully reversed, then R = -1.
If the stresses are partially reversed, R = a negative number less than 1.
If the stress is cycled between a maximum stress and no load, R = zero.
If the stress is cycled between two tensile stresses, R = a positive number less than 1.
Variations in the stress ratios can significantly affect fatigue life. The presence of a mean stress component has a substantial effect on fatigue failure. When a tensile mean stress is added to the alternating stresses, a component will fail at lower alternating stress than it does under a fully reversed stress.
tog Cycles to Failure
Preventing Fatigue Failure
The most effective method of improving fatigue performance is improvements in design:
Eliminate or reduce stress raisers by streamlining the part
Avoid sharp surface tears resulting from punching, stamping, shearing, or other processes
Prevent the development of surface discontinuities during processing.
Reduce or eliminate tensile residual stresses caused by manufacturing.
Improve the details of fabrication and fastening procedures Fatigue Failure Analysis
Metal fatigue is a significant problem because it can occur due to repeated loads below the static yield strength. This can result in an unexpected and catastrophic failure in use.
Because most engineering materials contain discontinuities most metal fatigue cracks initiate from discontinuities in highly stressed regions of the component. The failure may be due the discontinuity, design, improper maintenance or other causes. A failure analysis can determine the cause of the failure.
High Temperature Failure Analysis
Creep occurs under load at high temperature. Boilers, gas turbine engines, and ovens are some of the systems that have components that experience creep. An understanding of high temperature materials behavior is beneficial in evaluating failures in these types of systems.
Failures involving creep are usually easy to identify due to the deformation that occurs. Failures may appear ductile or brittle. Cracking may be either transgranular or intergranular. While creep testing is done at constant temperature and constant load actual components may experience damage at various temperatures and loading conditions.
Creep of Metals
High temperature progressive deformation of a material at constant stress is called creep. High temperature is a relative term that is dependent on the materials being evaluated. A typical creep curve is shown below:
Graph-2 strain-time curve
In a creep test a constant load is applied to a tensile specimen maintained at a constant temperature. Strain is then measured over a period of time. The slope of the curve, identified in the above figure, is the strain rate of the test during stage II or the creep rate of the material.
Primary creep, Stage I, is a period of decreasing creep rate. Primary creep is a period of primarily transient creep. During this period deformation takes place and the resistance to creep increases until stage II. Secondary creep, Stage II, is a period of roughly constant creep rate. Stage II is referred to as steady state creep. Tertiary creep, Stage II, occurs when there is a reduction in cross sectional area due to necking or effective reduction in area due to internal void formation.
Stress Rupture
Stress rupture testing is similar to creep testing except that the stresses used are higher than in a creep test. Stress rupture testing is always done until failure of the material. In creep testing the main goal is to determine the minimum creep rate in stage II. Once a designer knows the materials will creep and has accounted for this deformation a primary goal is to avoid failure of the component.
W2 ir5 105 101 W Stress rupture time, hr
Graph-3 stress - stress rupture time
Stress rupture tests are used to determine the time to cause failure. Data is plotted log-log as in the chart above. A straight line is usually obtained at each temperature. This information can then be used to extrapolate time to failure for longer times. Changes in slope of the stress rupture line are due to structural changes in the material. It is significant to be aware of these changes in material behavior, because they could result in large errors when extrapolating the data.
CHAPTER - 3 SPECIFICATION OF HEAT EXCHANGER PARTS
THE CHANNEL COVER
Channel covers are usually circulars in design and fabricated out of the same
plate material as the channel. The thickness of the flat channel covers in determined from code or TEMA formulas whichever is greater. For single pass channels or other in which there is no pass partition gasket seal against the channel cover. Only the code formula needs be considered. The effective thickness of the flat channel covers is the thickness measured at the bottom of the pass partition grove minus the tube side corrosion allowance in excess of the grove depth. Channel covers are required to be provided with approximately 3/16 " (408m) deep groves for pass partition plates.
THE CHANNEL
The channel is usually rod plate material with the edges welded together by a full
penetration fusion weld. This weld is a longitudinal seam. The stationary flanges of the channel are welded in the same manner are circumferential weld seam.
The pass partitions in the channel are flat plate and the same material as the channel. They are usually attached to the inside of channel by fall penetration fusion weld. The nominal thickness of channel pass partitions shell not be less than that shown in the table given below. Partition plates may be tapered to gasket width at the contact surface.
LONGITUDINAL WELD SEAM
CHANNEL
figure-12
Minimum pass partition plate thickness
Nominal size carbon steel alloy
Less L24" 3/8" %"
24"to 60" Y2" 3/8"
THE SHELL
Construction and fabrication of an exchanger are similar to that of pressure vessel. The exchanger's shell material is usually rolled plate material. The plate edges are welded together by a full penetration fusion weld. This weld is the longitudinal weld seam. The exchanger may require two or more shell rings joined together to form a single exchanger shell. The welds joining the rings together are circumferential weld seams. For small diameter exchangers, seamless pipe is usually used.
The shell thickness of the exchanger is determined by code design formulas plus corrosion allowance, but is no case shall the nominal thickness of the shell be less than that shown in the TEMA table given below.
EXCHANGER SHELL
figurel3
gasket seating surface
TEMA Minimum shell Nominal thickness Carbon steel Nominal shell
Diameter pipe plate Alloy
8"-12" 8CH.30 1/8"
4
13"-29" 3/8" 3/8" 3/16"
30"-39" 7/16"
40"-60" _ lA" 5/16"
For AES exchangers and the other types of exchangers flanges are in accordance with code design rules. Flages are through-bolted type unless otherwise specified. The shell flange to shell welds are circumferential weld seams and are also full penetration fusion welds.
Note : All weds on the inside of the exchanger shell are ground flush with the base material so the tube bundle with slide in and out of the shell without hanging up.
SHELL COVER
The shell cover thickness is determined by code design formulas plus corrosion allowance. For shell covers, TEMA requires the thickness of the shell cover to be at least equal to the thickness of the shell cover to be least equal to the thickness of the shell as shown given previous page. The material used to fabricate the shell cover is the same as the shell material.
The body of the shell cover is usually roved plate material with the edges together with a full penetration fusion weld. The head used for the shell cover is normally a flanged and dished type. Both the head the flange are welded to the body of the head with a full penetration fusion weld.
NOZZLES
Nozzles may be fabricated out of pipe coupling, built up construction, long weld neck flanges as integrally reinforced nozzles. The intergrally reinforced necks are preferred. Shed nozzles are not permitted to protrude beyond the inside contour of the shell. Channel nozzles may protrude inside the channel, provided vent and drain connections are flush with the inside contour of the channel. Vents and drains on the shell side of the exchanger not other wise vented or drained by nozzles are required to have a 3/4" connections may be provided at the manufacturers obtain.
K;ii:i FACT
L
J 1
J
1 * T I WIT:F HOLE
i .j
i
J i k. . my.
JKm.^Ju 1 L, X
Nozzle
Figure 14
Flat on raised flanges are required between intermediate nozzles of stacked units. Bolting in flanges of mating connections between stacked exchangers is required to be removable without moving the exchangers. All nozzles are required to be full penetration fusion welds with the inside of the weld to be flush on all shell connections.
TUBE SHEETS
The tube bundle of the AES exchanger has a stationary tube sheet on the channel end of the bundle and a floating head tube sheet on the back end of the bundle. The diameter of the floating head tube sheet is small enough to pass through the cylindrical shell. The diameter of the stationary tube sheet is larger enough to bear on a gasketed surface of the shell flange - stationary end. Tube sheets may be the same material as the tubes or may be of a different metallurgy that the tube. Because of economics a cooler or condenser may have brass tubes and carbon steel tube sheet. From corrosion standpoint it is not good to mix metallurgy like this in water service because of galvanic corrosion between the brass tube and carbon steel tube sheet. Life of the carbon steel tube sheet can be extended by adding cathodic protection in the channel and the floating head during fabrication or after the unit arrives at the refinery.
Tube sheets may also be alloy lined by cladding or weld metal overlay for corrosion resistance. Cladding should be integrally and continuously bonded to the base material of the tube sheet and is not counted for the strength is adds to the base material. The TEMA nominal cladding thickness on the tubeside face of a tube sheet is to be note than 5/16" (8mm) when tubes are expanded only, and 1/8" when tubes are welded to the tube sheet. The nominal cladding thickness of the shell side face shall not be less than 3/8". All surfaces exposed to the fluid including gasket seating surfaces, are required to have at least 1/8" nominal thickness of cladding.
The circular tube sheets are machined to the required dimensions including gasket seating surfaces. Tube holes are drilled and reamed for the tubes. If the tube sheets require heat treatment, the final hole size is obtained by reaming after heat treatment.
Tubes are usually attached to the tube sheet by rolling. A suitable roller type tube expander should be used to tighten tube. Care must be taken to insure that the tubes are not over expanded, thus avoiding possible damages to the tube.
All tube sheet tube holes for expanded joints are required by TEMA to have at least two machined grooves each, approximately 1/8" (3mm) wide by 1/64" deep. Tubes are normally expanded into the tube sheet for a length not less than 2" or tube sheet thickness minus 1/8" whichever is smaller. In no case should the expanded portion of the tube extend beyond the shell side face of the tube sheet. The expanding procedure should provide uniform expansion throughout the expanded portion of the tube without sharp transition to the unexpanded portion. Tubes for the top tube sheet in vertical exchangers are required to be flush to facilitate drainage. Tubes may also be rolled and seal welded for additional leak tightness or strength welded.
BAFFLES AND TUBE SUPPORTS
Baffles are used to channel the shell side fluid around the tubes from the shell inlet to the shell outlet. The various types of baffles used in tube bundle construction are illustrated in figure. The segmental or multi-segmental type of baffles or tube support plate is standard, but other type of baffles may be used. The baffles are circular plate with a segment opening and the height of this opening is a percentage of the shell inside diameter. The baffle material may be the same as the shell or tube material, depending on what was specified by the purchaser.
Baffles tube holes are usually drilled into the baffles. When the maximum unsupported tube length is 914 mm or less, or tubes larger in diameter than 33 mm diameter and greater, standard tube holes are drilled 0.4 mm over the outer diameter of the tubes. For pulsating conditions, tube holes may be drilled smaller than standard. All baffle holes drilling has a maximum over tolerance of 0.25 mm.
Standard cross baffle and support plate clearance (all dimensions are
in inches)
Nominal shell inside diameter Design inside diameter of shell minus baffle out side diameter
8-13 0.100
14-17 0.125
18-23 0.15
24-39 0.175
40-54 0.225
55-60 0.30
Table-1 Standard cross baffle and support plate clearance
The design inside diameter of the pipe shell is the nominal outside diameter of the pipe, minus twice the nominal wall thickness. The design inside diameter of a plate shell is the specified inside diameter,
Special design consideration must be given to baffles and support plates subjected to pulsations, to baffles and support plates engaging tubes, and to laongitudinal baffles subjected to large differential pressures due to high shell side fluid pressure drops.
Baffles and support plate spacing are normally spaced uniformly, spanning the effective tube length. When the design is such that this cannot be done, the baffles nearest the ends of the shell are and tube sheets are located as close as parctical to the shell nozzles. The remaining baffles are then spaced uniformly.
THE RODS AND SPACERS
The baffles or support plates of a bundle are tied together with tie rods and spacers. They hold the baffles or supports securely in position during the fabrication of the bundle. The tie rods are normally rod material and the spacers tubing. The material of both should be similar to that of the tubes. In some cases, because of economic, some refineries have carbon still tie rods and spacers in a brass tube bundle.
SEALING DEVICES
In addition to baffles it may be necessary to prevant excessive fluid by passing around or through the tube bundle that has a longitudinal baffle or baffles, particularly in the case of type F, G, H or J shells. The most common sealing device is seal strips but tie rods with spacers, dummy tubes or any combination of these may be used. Seal strips are made up of very thin metal strips sandwiched together and bolted to both side of the bundle. When the bundle is inserted into its shell the seal strips make contact with the side of the shell, thus providing the seal.
IMPINGEMENT BAFFLES AND EROSION PROJECTION
An impingement plate, or other means to protect or curtail erosion to the shell side of the tube bundle from incoming fluids may be required if they exceeds certain entrance line values as determined by a formula given into the TEM standard. Normally the impingement plate is made out of plate material similar to the bundle material and is either welded or brazed to the tie rods of the bundle. The impingement plate should never be attached to the tubes. A properly designed diffuser may be used to reduce line velocities at the shell entrance or inlet nozzle. The diffuser material should be the same as the shell material.
FLOATING HEAD
The most common type of floating head is the flanged and shallow dished. The floating head may be bolted directly to the floating head tubesheet of the bundle or may be attached by a backing ring device. The material of construction for split rings or other internal floating head backing devices is the same as the material used for sheel interior.
Pass partition, plates, when required, are usually plate material which is cut to be contour of head and attached to the head by a full penetration fusion weld.
BOLTING
Except for special design consideration, flanges are through bolted with stud bolts threaded full length with a removable not on each end. Stud bolt length should be such that the nuts are fully engaged and project through approximately 3.2 mm on each end. The minimum permissible TEMA bolt diameter is 3/4" (19 mm). For sizes 1" (25.4 mm) ans smaller, coarse thread series is required by TEMA and for larger sizes an 8 - pitch thread series is required.
CORROSION ALLOWANCE
Pressure Parts: All carbon steel pressure parts, except tubes, have a corrosion allowance of 1/8" (3.2mm) unless service conditions make a different allowance more suitable and specified by the purchaser.
Internal Covers: Internal covers are to have a corrosion allowance on each side.
Tube Sheets: Tube sheets are to have corrosion allowances on each side with provisions that, on the grooved side of a grooved tube sheet, the depth of the pass partition groove may be considered as avilable for corrosion allowance.
External Covers: Where flat external covers are grooved, the depth of the groove may be considered as available for corrosion allowance.
End Flanges: Corrosion allowance apply only to be inside diameter of the flanges.
Non Pressure parts: Non pressure parts such as tie rods, spacers, baffles and support plates have no corrosion allowances.
Floating Head Backing Device: Floating head backing devices and internal bolting have no corrosion allowance.
Pass Partition Plates: Pass partition plates have no corrosion allowance unless, specified by the purchaser.
Alloy Parts: No corrosion allowance is added to alloy parts except as specified by the purchaser. When weld metal overlay cladding or cladding is used, the nominal thickness of the cladding is usually the available corrosion allowance.
Tubes: Unless specified by the purchaser the corrosion allowance for tubes may be arbitrarily set at between one half and one third the original nominal thickness, depending on service and experience.
SUPPORTS AND FOUNDATIONS
All tubular exchangers are required to be provided with supports which are designed to avoid under stress or deflection in either the supports or shell. Horizontal units are provided with at least two supporting saddles with holes for anchor bolts. The holes in at least one of the supports are required to be elongated to provide for expansion of the shell. The saddles are mode of plate material rolled to the OD. The plate material should be the same material as the shell. The saddle is attached to the shell of the exchanger by a full filled weld and is welded all the way around. A vent hole or tell tale hole is drilled in the bottom of the saddle, max size 1/4" (6.4 mm), when the saddle is welded all the way around.
In some cases, a gap in the weld may be left near the bottom of the saddle for venting.
For vertical exchangers, supports of sufficient size are required to carry the unit in a supporting structure of sufficient width to clear shall flanges.
Foundation must be designed so that the exchanger will not settle and cause the piping to transmit excessive strains to the nozzles of the exchanger. Foundation bolts should be set to allow for setting inaccuracies. In concrete footings, pipe sleeves at least one size larger than the belt diameter slipped over the bolt and cast in plate are best suited for this purpose, as they allow the bolt centre to be adjusted after the foundation is set.
Foundation belts should be loosened at one end of the exchanger to allow free expansion of the shell. The slotted helps in the supports are provided for this purpose.
The exchanger must be set level and square so that pipe connections may be made without forcing.
GROUND WIRE
All exchangers are provided with a ground wire in case they are struck by lighting. This ground wire is attached to one of the foundation bulbs on one end of the exchanged and runs down into the ground.
LIFTING DEVICES
Channel, bonnets, floating heads and shell covers which weight over to pounds are required to the provided with lifting legs, rings or tapped holes for eyebolls for lifting.
EXCHANGER GASKETS
All gaskets are required to be made in one piece, but does not exclude gasket made integral by welding. Metal jacketed or solid metal gaskets are required for floating head joints, all joints for pressures of zoops ; and over, and for all joints in contact with hydrocarbons. Other gasket material may be specified by agreement between the purchaser and the manufacture to meet special service conditions and flange design. We two gaskets are compressed by same bolting, gasket material and areas shall be selected so that both gasket seal, but neither is crushed at the required bolt load.
CHAPTER -4 PROBLEM DEFINITION
In HOCL a shell and tube heat exchanger is used in the production line of phenol. Hot oil at 328 C and 10.5 kg/cm2 is passing through the exchanger tubes.SS316 material is used in the tubes. 120 tubes at the top of the heat exchanger fails regularly and hence the plant have to be closed down for at least 2 days on each failure. The failure causes lose of hot oil (therminol) which cost approximately Rs 850 per litre. About 1cm drop in oil level costs about 5 lakhs.
CHAPTERS CAUSES OF FAILIURE
5.1 Vibration
Damage from the tube vibration has become an increasing phenomenon as
heat exchanger sizes and quantities of flow have increased .The shell side flow
buffle configuration and unsupported tube span are of prime consideration
mechanism of tube vibration are follows.
Vortex shelling
I he vortex shelling frequency of the fluid in cross flow over the tubes may coincide with a natural frequency of tube and excite large resonant vibration amplitudes
Fluid elastic coupling
Fluid flowing over tubes causes them to vibrate with a whirling motion .the mechanism of fluid elastic coupling occurs .When a critical velocity exceed and the vibration then become self exited and grows in amplitude .This mechanism frequently occurs in process heat exchangers which suffer vibration damage .
Pressure fluctuation
Turbulent pressure fluctuations which develop in the wake of a cylinder or are carried to the cylinder from upstream may provide a potential mechanism for tube vibration .The tube respond to the portion of the energy spectrum that is close to their natural frequency.
5.2 Corrosion
High temperature in the system can cause oxidation due to its cause corrosion. Chemical reactions of hydrocarbon can also causes corrosion.
5.3 Over heating of 120 tubes at the top.
In the shell and tube heat exchanger at the inlet (bottom of the shell) hydrocarbon is in liquid state.
The inlet temperature of hydrocarbon is 217 c. out let temperature is 229 c.
The heating fluid hot oil called Therminol passess through the tubes. The inlet of hot oil is at top of the bundle and outlet is at the bottom The inlet temperature of the hot oil is 320 c. and the outlet temperature is 270 c. If there is any obstruction or processing delay in the production line it causes the shortage of hydrocarbon supplay in to the heat exchanger. During when the hot oil will be pass through the tubes this converts the top hydrocarbon in bundle to vapour state. In the vapour state convective heat transfer (h) is less. This causes the top 120 ube become overheat.
CHAPTER-6 TYPE OF FAILURE
6.1Tube bracking
The corrosion and erosion in the tube can cause tube brakeage
6.2Fracture in the weld portion
The clearance between the shell and tube bundle can cause vibration in the tube bundle. This cause the fracture formation in the tube sheet.
6.3Tube bending
The clearance between the shell and tube and over heating can cause the bending of tubes.
CHAPTER-7 CHECKING THE DESIGN
1. Constructional details
Inside diameter of the tube 'dr
Thickness of the tube
Out side diameter of the tube 'do'
In side diameter of the shell
Number of the tubes
Number of the pass
2. Details of hot oil
Dynamic viscosity
Density
Thermal conductivity
Specific heat
3. Details of aromatic hydrocarbons
Dynamic viscosity
Density
Thermal conductivity Specific heat
14.83mm
4.22mm
19.05mm'
934mm
360
6
0.2centi poise 20*10"4NS/M2 0.807kg/m3 0.095kcal/hnn c 0.1108w/m c 3.3518kj/kg c
0.93centi poise
93*10"4NS/M2
0.820kg/m3
0.1kcal/hrm c
0.1167w/m c
2.356kj/kg c
4. Length of the tube
Average length of the tube
5. Operating conditions
Mass flow rate of hot oil 'mh'
One time oil passes 120 tubes Mass flow rate of aromatic hydro carbons 'mc" Inlet temperature of hot oil 'Thi'
=2408102/360
=6689mm
=6.689mm
=66173kg/hr -66173/3600*120 =0.153kg/sec =64708 kg/hr = 17.98kg/sec =320 c
Out let temperature of hot oil 'tho* =270 c
Inlet temperature of aromatic hydro carbons 'Tcj' =217 c
Outlet temperature of aromatic hydro carbons 'Tco' =230 c
6. Calculation
Log mean temperature difference= (^ Tl - ^T2)/ln ( AT1/AT2)
AT1 = Th,-Tco
=320-230 =90 c
AT2 =Th0-Tci
=270-217 =53 c
LMTD = (90-53)/ln (90/53)
=69.87 c
The multi pass cross flow heat exchanger, LMTD =F*LMTD
Correction factor 'F* find from heat transfer data book using Temperature ratio 'P' and Capacity ratio 'R'
Temperature ratio 'P'= (Rise in temperature of the cold fluid) / (Difference in inlet temperature of the two fluids)
P = (TCo-Tci)/ (Tho-Tci) = (230-217)/ (320-217) -0.126
Capacity ratio 'R'= (Temperature drop of hot
Fluid) / (Temperature drop of cold fluid)
R - (Tho-Thj)/ (Tco-Tci) = (320-270)/(230-217) = 3.8
Correction factor from data book chart =1 LMTD =1*68.87 =69.87 c
A .consider flow inside the tube
Mass flow rate of hot oil inside the tube "mh'=0.153kg/sec
Reynolds number 'Re'
= (4* rrih) / (3.14*di *dynamic viscosity) = (4*0.153)/ (3.14*0.01483*20* 10 4) = 6578.28
Reynolds number 'Re' greater than 2300 so flow is turbulent
In the case of turbulent flow Nusset number "Nu'
= 0.0238*Re08 Pr04
Prandtl number 'Pr'
= (dynamic viscosity*specific heat)/ (thermal conductivity
of hot oil)
= (20*10"483.318*103)/0.H08 = 59.89
Nu = 0.023*6571.28 08*59.89 04
=138.9
Convective heat transfer coefficient 'hi'= (Nu*k)/di
= (138.69*0.1108)/0.01483 = 1036.2w/m2k
B. Consider flow over the tube
The flow over the tube due to natural convection Prandtl number 'Pr'
= (dynamic viscosity*specific heat)/ (thermal conductivity of aromatic hydro carbons)
= (3* 10"4*2.356*103)/0.1167 = 188.13
Grashof number 'Gr = (L3(3 g t)^v2
Gr = (6.089 3 *0.00176*9.81 *71.5)/( 11.34*10'3)2 =2.878*106
Where
Length of the tube 'L'=6.689m (3 = volumetric expansion=l/T = 1/(295+273) = 1.760* 10"3k"'
Assume surface temp of tube is The mean temp of the hot oil 'T' = (320+270)/2=295 c
/\t = tube temp - fluid temp =295- ((230+217)/2) =71.5 c
v -dynamic viscosity/density = (93*10"4)/0.820 = 11.34*10"3m2/s
Gr*Pr = 2.87*106 * 188.18 = 0.539*109
Nu = 0.53(Gr*Pr) 1/4 for (104< Gr*Pr>109) =0.53(0.539*109 *188.18)025 =87.42
Nu=h0d0/k
h0 =(87.42*0.116)/ (19.05*10 3) =494.74w/m2k
Overall H.T coefficient
'If =1/ ((do/ (di*hi)) + ((do/2k) In (do/di)) + (1/ho))
= 1/ ((0.0195/ (0.01483*1036.4)) + ((0.01905/2*13.6) In (0.01905/0.01483)) +
(1/494.724))
=290.0599w/m2oc
Heat transfer rate cold fluid
Q =mc cpc (Tco-Tci)
Where mc =17.98kg/sec Cpc =2.356kj/kgoc Tco =230 c Tci =217 c
Q =17.98*2.356*10 3*(230-217) = 550521.28w
Heat transfer rate hot fluid
Q = mh cph (Th0-Thi)
Where mh =0.153kg/sec
Cph =3.318kj/kg c
Tco =320 c
Q = 0.153*3.318*10 3*(320-270) Tci =270 c
Q =120*25382.7.7w (one pass has 120 tubes)
= 3045924w
Q =U* A* LMTD
A =Q/ (U*LMTD)
Area required for the heat transfer = 3045924/ (29005*69.87) = 150.1m2
Actual area =3.14*do*L
=3.14*.01905*6.689*360
= 144.040m2 Actual area =144.040m2 *103%=148.36 Actual area < area required for the heat transfer So design is not safe
CHAPTERS C-PROGRAMING OF DESIGN
#include<stdio.h> #include<conio.h> #include<math.h> void main()
{
double rN,nNl,nN2,pNl,pN2,gN;
//Reylolds Number, Nusselt Number 1 &2, Prandtl Number 1&2, Grashoff Number, double p=0,r=0;
double iTHO; /* Inlet temperature of hot oil Thi (320 Degree C)*/
double oTHO; /* Outlet temperature of hot oil Tho (270 Degree C)*/
double mTHO;/*Mean Temperature of Hot Oil*/
double iTCO; /* Inlet temperature of Cold oil Tci (217 Degree C)*/
double oTCO; /* Outlet temperature of Cold oil Tco (230 Degree C)*/
double mTCO;/*Mean Temperature of Cold Oil*/
double iDT ; /* Inside diameter of the tube = 14.83mm */
double oDT; /* Outside diameter of the tube =19.05mm */
double nT; /* Number of the tubes = 360 */
double pass; /* Number of the pass = 6*/
double mFRPHO;/* Mass flow rate of hot oil =66173kg per hr*/
double mFRSHO; /* Mass Flow Rate of Hot Oil Per Second through 1 tube = 0.153
kg/sec*/
double mFRAHC;/* Mass flow rate of Aromatic Hydro Carbon = 64708 kg/hr */ double mFRPSAHC; /* Mass Flow Rate of Aromatic Hydro Carbon Second = 17.98
kg'sec*/
double dVHO;/* Dynamic viscosity hot oil =0.2centi poise =20*10-4 Ns/m2*/ double dHO; /* Density hot oil =0.807kg/m3*/
double tCHO; /* Thermal conductivity hot oil =0.095kcal/hrmc =0.1108w/moc*/ double sHHO; /*Specific heat hot oil = 3.3518kj/kgoc */
double dVAHC=93*.0001; /*Dynamic viscosity aromatic hydrocarbons =0.93centi poise*/ =93*10-4 NS/M2*/
double kVAHC;/*Kinamatic Viscosity of Aromatic Hydrocarbon*/ double dAHC = 0.820;/*Density aromatic hydrocarbons=0.820kg/m3*/ double tCAHC = 0.1167;/* Thermal conductivity aromatic hydrocarbons =0.1 kcal/hrmoc = 0.1167w/moc */
double tCT= 13.3;/* Thermal conductivity of the tube material=13.3w/mk*/
double sHAHC=2.356; /*Specific heat aromatic hydrocarbons =2.356kj/kgoc*/
double aLT=0; /* Average Length of Tube */
double 1MTD=0; // Log Mean Temperature Difference//
double T1,T2=0;
double hTCI,hTCO=0;/*Heat Teanfer Coefficient at Inlet and Outlet*/ double oHTC=0; //Overall Heat Transfer Co-efficient// double hTRHO=0; //Heat Transfer Rate of Hot Oil// double area=0; // Actual Area of Tube// double areaTh = 0; //Theoretical Area of Tube//
clrscr();
//inputting values
printf("\nlnlet temperature of hot oil Thi in degree celcius:"); scanf("%lf',&iTHO);
printf("\nOutlet temperature of hot oil Tho in degree celcius:"); scanf("%lf',&oTHO);
mTHO=(iTHO+oTHO)/2.0;
printf("\nlnlet temperature of Cold oil Tciin degree celcius:"); scanf("%lf',&iTCO);
printf("\nOutlet temperature of Cold oil Tco in degree celcius:"); scanf("%lf',&oTCO);
mTCO=(iTCO+oTCO)/2.0;
printf("\nlnside diameter of the tube in meter:"); scanf("%lf',&iDT);
printf("\nOutside diameter of the tube in meter:"); scanf("%lf',&oDT);
printf("\nNumber of the tubes:"); scanf("%lf',&nT);
printf("\nNumber of the pass:"); scanf("%lf',&pass);
printf("\nMass flow rate of hot oil in kg/hr:"); scanf("%lf ,&mFRPHO);
mFRSHO =(mFRPHO)/(3600.0* 120.0); /* Mass Flow Rate of Hot Oil Per Second through 1 tube = 0.153 kg'sec*/
printf("\nMass flow rate of Aromatic Hydro Carbon kg/hr:"); scanf("%lf',&mFRAHC);
mFRPSAHC =(mFRAHC)/(3600.0); /* Mass Flow Rate of Aromatic Hydro Carbon Second = 17.98 kg/sec*/
printf("\nDynamic viscosity hot oil in centi pois:");
scanf("%lf',&dVHO);
dVHO = dVHO*0.01;
printf("\nDensity hot oil in kg/mA3:"); scanf("%lf',&dHO);
printf("\nThermal conductivity hot oil in w/rak:"); scanf("%lf',&tCHO);
printf("\nSpecific heat hot oil in j/kg k:"); scanf("%lf ,&sHHO);
printf("\nDensity aromatic hydrocarbons kg/'mA3:"); scanf("%lf',&dAHC);
printf("\nThermal conductivity aromatic hydrocarbons w/mk:"); scanf("%lf',&tCAHC);
printf("\nThermal conductivity of the tube material w/mk:"); scanf("%lf',&tCT);
printf("\nSpecific heat aromatic hydrocarbons j/kg k:"); scanf("%lf',&sHAHC);
printf("\ndynamic viscosity of aromatic hydrocarbon in NS/mA2:");
scanf("%lf',&dVAHC);
printf("\nAverage Length of Tube in meter:");
scanf("%lf',&aLT);
Tl=iTHO-oTCO;
T2=oTHO-iTCO;
lMTD=(Tl-T2)/(log(Tl/T2));
p=(oTCO-iTCO)/(oTHO-iTCO);
r=(oTHO-iTCO)/(oTCO-iTCO);
printf("%lf %lf\t",p,r);
rN=(4*mFRSHO)/(3.14*iDT*dVHO); printf("Reynolds Number =%lf\t",rN); if(rN>2300)
\
pNl-(dVHO*sHHO.)/(tCHO); printf("Prandtl Number l=%lf\t",pNl);
nN 1 -0.023 8*(pow(rN,0.8))*(pow(pN 1,0.4)); printf("Nusselt Number l=%lf\t",nNl);
printf("Inner Diameter of Tube = %lf Thermal conductivity hot oil =%lf
\t",iDT,tCHO);
hTCI=(nNl*tCHO)/iDT;
printf("Heat Transfer Coefficient at Inlet =%lf\t",hTCI);
}
pN2=(dVAHC*sHAHC)/(tCAHC); printf("Prandtl Number 2=%lf\t",pN2);
mTHO=(iTHO+oTHO)/2; mTCO=(iTCO+oTCO)/2; kVAHC=dVAHC/dAHC;
printf(" Average Length of Tube =%lf\t Mean Temperature of Hot Oil =%lf\t Mean Temperature of Cold Oil =%lf\t",aLT,mTHO,mTCO);
gN=(pow(aLT,3)*( 1 /(mTHO+273))*9.81 *(mTHO-mTCO))/(pow(kVAHC,2)); printffGrashoff Number = %lf\t",gN);
if((gN*pN2)<=pow(l 0,9))
\
nN2=0.53*pow(gN*pN2,0.25); printf("Nusselt Number 2 =%lf\t",nN2);
}
else {
nN2=0.13*pow(gN*pN2,0.33);